As coal is mined, a large amount of methane gas accumulates in the mine. Sometimes this methane gas is simply vented to the atmosphere or burned off. At other times, it is allowed to accumulate.
Much attention has recently been focused on emission standards, particularly for high volume public utilities such as power plants. Power plants commonly use co-firing boilers to produce electricity. However, much of the coal available in the United States has high contents of sulfur dioxide or nitrogen dioxide, two substance emissions which are particularly undesirable for the environment. Many environmental regulations require the reduction of the use of high sulfur content coal in public utilities. One alternative to meeting these emission standards is to pay a penalty for such sulfur dioxide emissions. It is therefore an object of this invention to provide an economical alternative to the payment of these environmental penalties due to the burning of sulfur dioxide laden coal.
Many coal boilers which emit sulfur dioxide, nitrogen dioxide, and green house gases (GHG) are currently in use in the United States. However, these boilers may be easily converted to a co-firing system at a low capital cost. This ease of conversion, along with the economic value of the converted system, make co-firing coal with gas a low risk approach to using coal mine gas as a substitute for coal. Co-firing with gas improves ash quality, reduces slag build-up, and can slightly increase boiler efficiency. The gas fuel input may vary from less than 3% to 100% of the total fuel input, increasing the short term peaking capability of the coal fire burner.
Many utility boilers now have co-firing capabilities, many of which are situated near gassy coal mines. Gassy coal mines are coal mines in which a large amount of methane gas exists. The methane gas is absorbed by the underground coal and seeps out in salvageable quantities.
In order to determine which boilers would be ideal for co-firing with coal mine gas, operators must consider the gas demand and availability, pipeline distances, and boiler conversion costs. Because co-firing is an ideal application for variable quality coal mine gas, the U.S. EPA is researching the economic potential to site new co-fired boilers at gassy coal mines to employ coal, coal mine gas, and ventilation air as fuels. One other alternative to siting these boilers at or near gassy coal mines is to develop an economical way to recover the methane gas from the mine and economically transport it to already existing boiler sites.
It is therefore another object of this invention to provide an alternative means of transportation for coal mine gas, involving a set of specially prepared tankers to transport the methane coal mine gas from the mine to the consumption site.
While co-firing gas at co-fired industrial and utility boilers is economically compelling, heretofore there have been great difficulties encountered in the transportation of the coal mine gas to suitable end-user facilities. If a method could be devised to economically capture coal mine gas into tanks and if transportation costs could be held down, the economies of the use of coal mine gas would be greatly increased. In addition, emission credits and avoided penalties could substantially improve the economics of most coal mine gas projects, thereby stabilizing coal use for utilities. It is therefore a still further object of this invention to provide a suitable means of transportation for recovered coal mine gas which partially uses the coal mine gas recovered as fuel for the transportation means.
It is also an object of this invention to provide a suitable means of transportation for recovered coal mine gas which is transported to a gas processing plant, where the inerts are removed such as nitrogen, carbon dioxide, and hydrogen sulfide and water. After the removal of the inerts, the gas is then pipeline quality, where it can be put into a major pipeline as Natural Gas.
A major problem with the collection of coal mine gas is that methane cannot be economically collected for transport because the coal mines in which the gas exists are spread out over a large area. The large area would require miles of pipeline. However, existing utility pipelines cannot be used because the nitrogen and carbon dioxide levels in the methane gas are too high for pipeline gas quality. Further, methane will not liquefy like propane gas unless it is frozen to 210 degrees below zero by use of cryogenics. The cryogenic solution is quite costly.
Also, it has been found that the production of coal mine gas from one area is not typically enough to economically justify the installation of a small gas processing plant. It takes several areas which are typically far apart, making the laying of pipeline to join those areas to one localized gas processing plant not economically feasible.
If methane gas is introduced into a bulk transport system or Compressed Natural Gas (CNG) System tanker, hereinafter also referred to by the term “tanker”, to transport, the costs are very high due to the expensive vessels of the tankers that hold the gas at high pressures, at or above 3000 psi. The vessels for holding the gas at the compression site are costly due to taking twice as much volume to load the transport quickly. Also, unloading takes time, such that the transport has to be left while the end user such as a gas processing plant, takes the gas from the tanker at a reasonable rate into the plant for processing. To unload quickly presently takes expensive tanks at the unloading facility, and the tanks are typically required to have twice the volume for the tanker, to allow the tanker to be unloaded quickly.